Abstract:

A piggable pipeline system is disclosed. One or more pig
launcher/receivers may be coupled to a pipeline. At least one fitting may
be coupled to the pipeline. The fitting may include a body and at least
two passages through the body. The passages are in fluid communication
within the body. A diverter is located in at least one of the passages.
The diverter is movable between an open position and a closed position.
In the open position, the diverter allows open flow between two of the
passages. In the closed position, the diverter inhibits flow between the
two passages. The pipeline may allow a pig to be launched from at least
one of the pig launcher/receivers and returned through the pipeline to at
least one of the pig launcher/receivers.

Claims:

1-34. (canceled)

35. A piggable pipeline system, comprising:a pipeline;one or more pig
launcher/receivers coupled to the pipeline;at least one fitting coupled
to the pipeline, the fitting comprising:a body;at least two passages
through the body, wherein the passages are in fluid communication within
the body;a diverter located in at least one of the passages, the diverter
being configured to be movable between an open position and a closed
position, wherein in the open position the diverter allows open flow
between two of the passages, and wherein in the closed position the
diverter inhibits flow between the two passages; andwherein the pipeline
is configured to allow a pig to be launched from at least one of the pig
launcher/receivers and returned through the pipeline to at least one of
the pig launcher/receivers.

36. The system of claim 35, wherein the system is configured to allow the
pig to be launched into the pipeline and received from the pipeline
without a return pipeline being coupled to the pipeline.

37. The system of claim 35, further comprising a host platform coupled to
the pipeline.

38. The system of claim 37, wherein the pig launcher/receiver is coupled
to the host platform.

39. The system of claim 37, wherein the system is configured to allow the
pig to be launched into the pipeline from the upstream of the system and
received from the pipeline without an additional pipeline being coupled
to the system.

40. The system of claim 35, further comprising at least one tie-back
system coupled to the pipeline, wherein the tie-back system is configured
to reverse the direction of travel of the pig through the pipeline.

41. The system of claim 40, wherein the tie-back system is coupled to the
pipeline at or proximate to a subsea well.

42. The system of claim 40, further comprising at least one kicker line
coupled to the tie-back system, wherein the kicker line is configured to
provide fluid to push the pig along the tie-back system.

43. The system of claim 42, wherein the kicker line is configured to be
provided fluid from the system.

44. The system of claim 42, wherein the kicker line is configured to
provide fluid to the system.

45. The system of claim 35, wherein the fitting is operable using a
remotely operated vehicle (ROV), an autonomous underwater vehicle (AUV),
or human operator.

46. The system of claim 35, wherein the fitting is a subsea fitting.

47. The system of claim 35, wherein the system is a subsea system.

48. A piggable pipeline system, comprising:a pipeline;a pig
launcher/receiver coupled to the pipeline;at least two fittings coupled
to the pipeline, the fittings comprising:a body;at least two passages
through the body, wherein the passages are in fluid communication within
the body;a diverter located in at least one of the passages, the diverter
being configured to be movable between an open position and a closed
position, wherein in the open position the diverter allows open flow
between two of the passages, and wherein in the closed position the
diverter inhibits flow between the two passages; andtwo or more pipeline
branches coupled to the pipeline, wherein the branches are coupled to the
pipeline at the fittings.

49. The system of claim 48, wherein the system is configured to use only
one pig launcher/receiver.

50. The system of claim 48, further comprising a facility coupled to the
pipeline.

51. The system of claim 50, wherein the pig launcher/receiver is coupled
to the host platform.

52. The system of claim 48, further comprising at least one tie-back
system coupled to the pipeline, wherein the tie-back system is configured
to reverse the direction of travel of a pig through the pipeline.

53. The system of claim 52, wherein the tie-back system is coupled to the
pipeline at or proximate to a subsea well.

54. The system of claim 48, wherein the fitting is operable using a
remotely operated vehicle (ROV), an autonomous underwater vehicle (AUV),
or human operator.

55. The system of claim 48, wherein the fitting is a subsea fitting.

56. The system of claim 48, wherein the system is a subsea system.

57. A piggable subsea pipeline system, comprising:a pipeline;at least one
subsea fitting coupled to the pipeline, the fitting comprising:a body;at
least two passages through the body, wherein the passages are in fluid
communication within the body;a diverter located in at least one of the
passages, the diverter being configured to be movable between an open
position and a closed position, wherein in the open position the diverter
allows open flow between two of the passages, and wherein in the closed
position the diverter inhibits flow between the two passages; anda coiled
tubing insertion apparatus coupled to the fitting;wherein the fitting
allows coiled tubing to be inserted into the pipeline and fluid to be
pumped from a subsea well coupled to the pipeline.

[0003]The present invention relates to subsea pipelines and connectors
and/or fittings used in the pipelines. Some embodiments relate to
fittings to combine and/or redirect flow in the pipelines. More
particularly, the invention relates to a pipeline using the fitting to
facilitate pigging and/or cleaning of pipelines.

[0004]2. Description of Related Art

[0005]Pipeline systems (e.g., subsea pipeline systems) are a maze of
connected and interconnected pipeline segments that transport
hydrocarbons or related products from one point to another. The pipeline
connection points initiate at the wellhead or other sources (e.g.,
refineries, plants, vessels, or production vessels) and connect to
manifolds, offshore structures, onshore facilities, intermediate
processors, and, eventually, to final processing and distribution of the
products. Due to the expenses and flow issues of running dedicated
pipelines from the initiating point direct to processing stations,
shorter pipeline segments are joined to existing or larger pipelines to
create the product pipeline from the source (e.g., the initiating
wellhead) to the market (e.g., onshore stations).

[0006]Pipeline interconnects have been accommodated by placing tee-shaped
fittings with a perpendicular intersect into a pipeline to create what
has been known as a branch or lateral connection point. These connections
provide a means of combining the product from one line with another.
However, these connect ions do not allow or the passage of certain pigs
used for cleaning and inspection, sometimes referred to as solid-mandrel,
trained, or intelligent pigs. Combining the flow of two pipelines into
one line to allow for pigging by all common forms of pigs requires the
use of a fitting known as a piggable wye.

[0007]Piggable wye fittings have relatively shallow intersect angles,
typically about 30° or less, which allow for fairly smooth
transmission of long pigs and pig trains from either of the two inlet
bores through the intersect and out through a common exhaust. However, if
a pig is ever run into the piggable wye in a reverse direction, the pig
will jam in the intersect of the wye, abnormally shutting down the
pipeline.

[0008]Reverse flow of a pipeline is becoming increasingly more common. To
this end, the ability to pig in the reverse flow direction is becoming a
more common consideration for pipeline design. Thus, a piggable wye
fitting that can be configured to suitably pass all forms of pigs in
normal (e.g., combining) flow conditions and in reverse (e.g., directed)
flow conditions is desirable.

[0009]The layout of a field development or pipeline system in which
production from a subsea well flows through a subsea pipeline, or
flowline, to a host platform may be referred to as a tie-back or subsea
tie-back. When certain physical and chemical conditions are anticipated
to exist in the production stream that will be transported in the
tie-back flowline, two pipelines have been installed to join the subsea
well with the host platform to form a pigging loop.

[0010]The ability to pig a subsea tie-back may be needed to effectively
send or launch a pig from the host platform via the first pipeline to the
subsea well or to the proximity of the well. The pig may be propelled
back to the host platform via the second pipeline. Such a pigging
operation allows the operator to help keep the pipeline system clear of
debris and or harmful matter as well as allow the operator to perform
other operational, inspection, and maintenance procedures.

[0011]Having a tie-back pipeline configured in a pigging loop has
typically required the installation of two pipeline runs from the host
platform to the subsea wellhead or in near proximity to the wellhead.
Both of these pipelines may require risers or lengths of pipe routed from
the sea floor to the host platform. On the host platform, each of the
pipelines is typically configured with a pig launcher and/or a pig
receiver. Such a host platform must be designed with enough physical
space to allow placement of the required pipe runs and pig
launchers/receivers for both pipelines.

[0012]In addition to the physical space required on the host platform
needed to accommodate the pipe runs and pig launcher/receivers, the host
platform must be designed with enough load carrying capacity to support
the two pipeline or flowline risers. If the host platform is a floating
structure, this additional load carrying capacity may be accommodated by
designing and building the host platform with additional buoyancy. If the
host platform is a template structure bearing its load on the seafloor,
the structure must be designed with appropriately sized deck beams and
supporting members as well as larger and adequately braced platform legs.
Such host platforms may be costly to manufacture, install, and/or
maintain. Thus, piggable pipelines that reduce the load carrying capacity
and physical space required on the host platforms are desirable. In
certain embodiments, a single pipeline pigging loop (e.g., a pipeline
loop that allows the pig to be propelled back to the host platform in the
same pipeline) may reduce the load carrying capacity and physical space
required on the host platform.

[0013]In some situations, the pipeline system may have more than one
pipeline branch that requires pigging. Certain pigs may not be usable in
such pipeline systems. For example, the pigs may not be able to negotiate
a "T" fitting that connects the pipeline branches. A separate pig
launcher and receiver may be needed to pig each pipeline branch. Using
multiple pig launchers and receivers results in expensive, voluminous,
heavy launcher and receiver barrels, and their associated piping, to be
installed for multiple pipeline branches. Thus, a pipeline system that
allows the pig to be propelled through multiple branches from a single
pig launcher/receiver is desirable.

SUMMARY

[0014]In certain embodiments, a subsea fitting includes a body with at
least two passages through the body. The passages are in fluid
communication within the body. A diverter may be located in at least one
of the passages. The diverter may be movable between an open position and
a closed position. In the open position, the diverter allows open flow
between two of the passages. In the closed position, the diverter allows
the passage of a pig in a specific passage in both directions.

[0015]In some embodiments, the two passages are oriented relative to each
other such that at least one of the passages is piggable in the reverse
direction. The two passages may be oriented with about a 30° angle
between the passages. The two passages may be oriented symmetrically
about a central axis.

[0016]In some embodiments, the diverter is coupled to the body using a
flange. The diverter may include a tubular that fits snugly inside the
passage, or have a non-interference fit with a gap between the diverter
and the body, and is allowed to rotate inside the passage. The tubular
may have an opening. In the open position, the opening allows open flow
between the two passages. In the closed position, the opening is
positioned so that open flow is inhibited between the two passages.

[0017]In some embodiment, the diverter includes orifices that allow at
least some fluid flow between the two passages to equalize pressure
between the two passages. The orifices inhibit object flow between the
two passages.

[0018]In some embodiments, a drive hub moves the diverter between the open
and closed positions. The drive hub may include teeth, castellations, or
other features that engage the diverter so that the drive hub is able to
move the diverter. A gear may be coupled to the drive hub to move the
drive hub. The gear may include teeth that engage teeth on the drive hub
so that the gear operates the drive hub. The coupling between the gear
and the drive hub may be substantially sealed from external pressure. The
gear may be operable using a remotely operated vehicle (ROV) or other
tool. A torque bucket, a hand wheel, a motor, or other operator may be
coupled to the gear.

[0019]In certain embodiments, a piggable pipeline system includes a
pipeline. One or more pig launcher/receivers are coupled to the pipeline.
At least one fitting is coupled to the pipeline. The fitting includes a
body, at least two passages through the body, and a diverter. The
passages are in fluid communication within the body. The diverter is
located in at least one of the passages. The diverter may be movable
between an open position and a closed position. In the open position, the
diverter allows open flow between two of the passages. In the closed
position, the diverter inhibits flow between the two passages. The
pipeline may allow a pig to be launched from at least one of the pig
launcher/receivers and returned through the pipeline to at least one of
the pig launcher/receivers.

BRIEF DESCRIPTION OF THE DRAWINGS

[0020]Features and advantages of the methods and apparatus of the present
invention will be more fully appreciated by reference to the following
detailed description of presently preferred but nonetheless illustrative
embodiments in accordance with the present invention when taken in
conjunction with the accompanying drawings in which:

[0021]FIG. 1 depicts a perspective representation of an embodiment of a
subsea fitting.

[0022]FIG. 2 depicts an end view of the subsea fitting depicted in FIG. 1.

[0023]FIG. 3 depicts a cross-sectional representation of the fitting
depicted in FIGS. 1 and 2 with a diverter in the fitting in an "open"
position.

[0024]FIG. 4 depicts a cross-sectional representation of the fitting
depicted in FIGS. 1 and 2 with the diverter in the fitting in a "closed"
position.

[0025]FIG. 5 depicts a cross-sectional representation of a portion of the
fitting depicted in FIGS. 1 and 2 with the bucket installed.

[0026]FIG. 6 depicts a cross-sectional representation of a portion of the
fitting depicted in FIGS. 1 and 2 with the bucket removed and a blind hub
installed on the operating mechanism.

[0027]FIG. 7 depicts a perspective view of a section of the subsea fitting
with a portion of the fitting sectioned to show the teeth on a gear
engaging the teeth on a drive hub.

[0028]FIG. 8 depicts a perspective view of an embodiment of a connector.

[0029]FIG. 9 depicts a cross-sectional representation of an embodiment of
a subsea fitting with two diverters with one diverter in the closed
position.

[0030]FIG. 10 depicts a cross-sectional representation of an embodiment of
a subsea fitting with two diverters with both diverters in the open
position.

[0031]FIG. 11 depicts an embodiment of a tie-back system with pigging
capability and a well energized kicker line.

[0032]FIG. 12 depicts an embodiment of a tie-back system with pigging
capability and a platform energized kicker line.

[0033]FIG. 13 depicts an embodiment of a tie-back system with pigging
capability and a small diameter kicker line.

[0034]FIG. 14 depicts an embodiment of a tie-back system with pigging
capability, a kicker line, and future pipeline system development.

[0035]FIG. 15 depicts an embodiment of a pipeline system for using a
single pig launcher/receiver with multiple pipeline branches.

[0036]FIG. 16 depicts an embodiment for using a subsea fitting for coiled
tubing access.

[0037]While the invention is susceptible to various modifications and
alternative forms, specific embodiments thereof are shown by way of
example in the drawings and will herein be described in detail. The
drawings may not be to scale. It should be understood that the drawings
and detailed description thereto are not intended to limit the invention
to the particular form disclosed, but to the contrary, the intention is
to cover all modifications, equivalents and alternatives falling within
the spirit and scope of the present invention as defined by the appended
claims.

DETAILED DESCRIPTION OF EMBODIMENTS

[0038]In the context of this patent, the term "fitting" means a fitting or
connector that may be coupled into a pipeline (e.g., a subsea pipeline,
slurry pipeline, or solid transport pipeline). The term "coupled" means
either a direct connection or an indirect connection (e.g., one or more
intervening connections) between one or more objects or components. The
phrase "directly connected" means a direct connection between objects or
components such that the objects or components are connected directly to
each other so that the objects or components operate in a "point of use"
manner. The term "open flow" means that flow is open to both fluid and
objects through a passage.

[0039]FIG. 1 depicts a perspective representation of an embodiment of
subsea fitting 100. FIG. 2 depicts an end view of fitting 100. Fitting
100 includes body 102. Body 102 may be made from materials such as, but
not limited to, carbon steel, stainless steel, titanium, aluminum,
plastic, or composite. In some embodiments, body 102 is a single piece
forged, cast, formed, or molded from any of the above listed materials as
well as other materials. In some embodiments, body 102 is constructed by
welding fabrication of plates, tubes, and forged or cast parts. Fitting
100 and body 102 may be operable in high pressure conditions due to the
pressurized contained product in the pipeline or ambient pressure from
deep subsea conditions. For example, fitting 100 and body 102 may be
configured to meet selected ASME (American Society of Mechanical
Engineers) standards, ANSI (American National Standards Institute)
ratings, ASTM (American Society for Testing and Materials) standards,
and/or DNV (Det Norske Veritas) standards. In some embodiments, body 102
is coated with a material to increase the strength, weldability, and/or
corrosion resistance of the body. For example, body 102 may be coated
with an epoxy such as Carboline 890® epoxy (Carboline Company, St.
Louis, Mo., USA).

[0040]In certain embodiments, fitting 100 is a wye-shaped fitting. Fitting
100 includes three ports 104, 106, and 108 on body 102. Ports 102, 104,
and 108 may be at the ends of one or more passages in body 102 (e.g., the
ports define the ends of the passages). Flanges may be coupled to one or
more of the ports. In certain embodiments, flange 110 is coupled to port
104. Flange 110 may be coupled to port 104 using bolts 112 or other means
such as welding, threads, or hubs that attach flange 110 to body 102 at
port 104. In certain embodiments, ports 104, 106, and/or 108 allow
fitting 100 to be coupled to one or more subsea pipelines and/or
additional fittings. In some embodiments, ports 104, 106, and/or 108 are
coupled to one or more subsea pipelines and/or additional fittings using
methods known in the art (e.g., welding). For example, pipe or connector
flanges may be welded to ports 104, 106, and/or 108 on fitting 100. In
some embodiments, flange 110 and/or other flanges allow fitting 100 to be
coupled to one or more subsea pipelines and/or additional fittings at
ports 104, 106, and/or 108.

[0041]In certain embodiments, bucket 114 is coupled to flange 110. Bucket
114 may be coupled to flange 110 using connector 116. In some
embodiments, connector 116 is coupled to bucket 118. In some embodiments,
as shown in FIG. 2, covering 120 may enclose at least a portion of bucket
114, connector 116, and/or bucket 118. Covering 120 may at least
partially protect bucket 114, connector 116, and/or bucket 118. For
example, covering 120 may protect bucket 114, connector 116, and/or
bucket 118 from being accidentally hit by objects in and around fitting
100 (e.g., a robotic arm, a digging tool, or other subsea tool).

[0042]FIGS. 3 and 4 depict cross-sectional representations of fitting 100
substantially along line A-A shown in FIG. 2. Passages 124 and 126 are in
fluid communication with each other inside body 102. Passages 124 and 126
may be conduits through all or portions of body 102. In certain
embodiments, passage 124 is a straight-through passage between port 104
and port 106. Passage 126 may branch off passage 124 to port 108 so that
the passages are in a wye-shaped configuration. Passage 126 may branch
off passage 124 at an angle that allows a pig to pass between the
passages. In certain embodiments, passage 126 branches off passage 124 at
an angle of about 30°. In some embodiments, passage 126 branches
off passage 124 at an angle between about 0° and about 90°.
In some embodiments, passage 126 branches off passage 124 at an angle in
a range from about 10° to about 90°, in a range from about
20° to about 70°, or in a range from about 25° to
about 60°.

[0043]In some embodiments, passage 124 and/or passage 126 include one or
more bends or other non-conformities as they pass through body 102. In
some embodiments, passage 124 and passage 126 are symmetrical about a
central axis (e.g., in a "Y"-shape about the central axis, as shown in
FIG. 9). In certain embodiments, fitting 100 is designed so that fluid,
slurry, or solids (e.g., oil) flow (e.g., oil flow) is through passage
124 from port 104 towards port 106 (in a right to left direction in FIGS.
3 and 4). Thus, a pig may enter fitting 100 through passage 126 via port
108 and be used to pig the pipeline in a reverse direction (e.g., a
direction reverse to a combining flow direction in the pipeline). Pigging
in the reverse direction of normal combining flow allows the pig to be
launched into and retrieved from the pipeline at locations more
convenient for the pipeline operator. Pigging in the reverse direction
also may allow certain pigging operations to be performed where they
would otherwise be more difficult or more costly. Passage 126 and passage
124 are designed and oriented so that any standard pig (e.g., a cup or
disc type pig, a smart pig, or an inspection pig) is usable with fitting
100.

[0044]As described above, flange 110 may be coupled to body 102 using
bolts 112. In some embodiments, bolts 112 are threaded bolts attached to
body 102 (e.g., the bolts are welded to the body, formed as part of the
body, or threaded into threaded openings in the body). Nuts or other
fasteners may be used to secure flange 110 to body 102 using bolts 112.
In certain embodiments, seal 122 is provided between flange 110 and body
102. Seal 122 may be, for example, a gasket or o-ring that when pressed
between the face of body 102 and the face of flange 110 creates a seal
between the faces. Seal 122 inhibits fluid (e.g., seawater or ambient
fluids) from entering passage 124 between the faces of body 102 and
flange 110 and inhibits fluid (e.g., pipeline fluid) from leaking out of
passage 124 into the surrounding environment. In some embodiments, flange
110 is coupled to body 102 by welding the flange to the body. Welding the
flange to the body allows the flange to be attached to the body without
bolts and without a seal.

[0045]In certain embodiments, flange 110 includes and/or is coupled to
diverter 128. Diverter 128 is a conduit (e.g., a sleeve or tubular)
located inside passage 124 and/or passage 126. In certain embodiments, as
shown in FIGS. 3 and 4, diverter 128 is within passage 124 and has a
clearance between the diverter's outside face and the passage's inside
face that allows the diverter to move (e.g., rotate) inside the passage
(e.g., the diverter is a tubular that fits snugly inside the passage (or
has a non-interference fit inside the passage) and is allowed to rotate
inside the passage).

[0046]In certain embodiments, diverter 128 includes opening 130. Opening
130 is an opening sized to allow fluid and/or objects (e.g., pigs) to
pass through diverter 128 between passage 124 and passage 126. In certain
embodiments, opening 130 is an elliptical or scarf-shaped cut in diverter
128. The cut may substantially match the shape of the junction of passage
124 with passage 126 when opening 130 is aligned with the junction. In
some embodiments, opening 130 has other shapes and/or sizes that match
the size and/or shape of a junction between passages in fitting 100.

[0047]Diverter 128 may move (e.g., rotate) to locate opening 130 in or out
of position to allow fluid and/or objects to pass between passage 124 and
passage 126. FIG. 3 depicts diverter 128 in an "open" position. In the
open position, opening 130 is in a position that allows fluids and/or
objects to pass between passage 124 and passage 126 (e.g., the passages
are in fluid communication or there is "open flow" between the passages).
FIG. 4 depicts diverter 128 in a "closed" position. In the closed
position, opening 130 is in a position that inhibits fluids and/or
objects from passing between passage 124 and passage 126.

[0048]In certain embodiments, diverter 128 includes one or more orifices
132. Orifices 132 may be small openings such as, but not limited to,
slots, slits, holes, or other perforations. Orifices 132 maybe located on
an opposite side of diverter 128 from opening 130 (e.g., diametrically
opposed to opening 130). In some embodiments, diverter 128 includes
orifices 132 substantially over its entire surface to allow for fluid
passage at all orientations of diverter 128. Orifices 132 are located on
diverter 128 so that when the diverter is in the closed position, the
orifices are positioned to allow at least some fluid to flow between
passage 124 and passage 126. Allowing at least some fluid flow between
the passages in the closed position may inhibit pressure differential
buildup between the passages (e.g., substantially equalize the pressure
between the passages). Allowing the flow between passages inhibits
lateral thrust loads on diverter 128 that may be caused by differential
pressures between the passages. Thrust loads may apply force to diverter
128 in its associated passage, which hinders rotation of the diverter. In
certain embodiments, orifices 132 are distributed on diverter 128 so that
thrust loads are minimized as the diverter begins to rotate. Orifices 132
may be sized to inhibit passage of certain objects (e.g., pigs) through
the orifices and between passage 124 and passage 126 while allowing fluid
to flow between the passages.

[0049]Diverter 128 may be moved (e.g., rotated) using a drive mechanism.
The drive mechanism may include drive hub 134. Drive hub 134 may be
located inside body 102 and coupled to, and/or contained by, flange 110.
In certain embodiments, drive hub 134 includes teeth 136 that engage with
teeth 138 on diverter 128. Teeth 136 may be formed as part of drive hub
134 or attached to drive hub 134 as a separate component (e.g., a ring
gear that is attached to the drive hub by, for example, bolting, welding,
or other attachment means). In some embodiments, teeth 136 and/or teeth
138 are castellations. When drive hub 134 is operated, teeth 136 engage
with teeth 138 to move (e.g., rotate) diverter 128 between the open and
closed positions. In certain embodiments, diverter 128 continuously
rotates in one direction (e.g., either a clockwise or counterclockwise
direction) to move between the open and closed positions. For example,
diverter 128 may rotate clockwise to move from the open to the closed
position. Rotating diverter 128 further clockwise moves the diverter from
the closed position back to the open position. In some embodiments,
diverter 128 is rotated in either direction to move between the open and
closed positions (e.g., the diverter is rotated clockwise to open the
diverter and counterclockwise to close the diverter). In certain
embodiments, one or more physical "hard" stops or limits are included in
fitting 100. The stops may be included to ensure that diverter 128
resides in a preferred position when it reaches the stops. For example,
fitting 100 may include stops at the fully-open position and at the
fully-closed position or at one or more locations in between the
fully-open position and the fully-closed position.

[0050]In certain embodiments, drive hub 134 is coupled to a drive operator
or gear that controls the operation (e.g., the rotation and orientation)
of diverter 128. FIGS. 5 and 6 depict cross-sectional representations of
fitting 100 substantially along line B-B shown in FIG. 2. FIG. 5 depicts
gear 140 coupled to drive hub 134. In certain embodiments, gear 140 is a
pinion gear. In certain embodiments, gear 140 includes a gear and a shaft
coupled to the gear.

[0051]Teeth on gear 140 may engage with teeth on drive hub 134 at point
142. In some embodiments, gear 140 and/or drive hub 134 interact via
belts, chains, castellations, or other mechanisms. FIG. 7 depicts a
perspective view of fitting 100 with a portion of the fitting sectioned
to show the teeth on gear 140 engaging the teeth on drive hub 134. In
certain embodiments, the teeth of drive hub 134 are an integral element
of the drive hub. In some embodiments, the teeth of drive hub 134 are a
separate component, such as a ring gear, which may be attached to the
drive mechanism by, for example, bolting, welding, or other attachment
means. In certain embodiments, the teeth on gear 140 and the teeth on
drive hub 134 are beveled. The beveled teeth may efficiently couple
operation of gear 140 to operation of drive hub 134, but other gear tooth
profiles such as spiral and worm gears may be used. Gear 140 may be
operated (e.g., rotated) to activate (e.g., rotate) drive hub 134. As
described above, operation of drive hub 134 moves (e.g., rotates)
diverter 128. In certain embodiments, drive hub 134 is integrated with
diverter 128.

[0052]In certain embodiments, gear 140 is able to operate under pressure
conditions (e.g., under subsea pressure conditions or pressurized fluid
conditions in the fitting). Gear 140 may pass through one or more seals
(e.g., seal 144 shown in FIGS. 5 and 6). As shown in FIGS. 5 and 6, seal
144 may be located inside connector 116. Seal 144 may be, for example, a
dynamic and/or bidirectional seal such as a lip seal, o-ring, or other
pressure-energized or enhanced seal. Seal 144 allows gear 140 to operate
under subsea and/or pipeline pressure conditions by pressure isolating
the internal operation of the gear (e.g., the coupling between the gear
and drive hub 134) from the ambient environment. In certain embodiments,
seal 144 allows gear 140 to operate at water depths of 10,000 feet or
more.

[0053]FIG. 8 depicts a perspective view of an embodiment of connector 116.
It is to be understood that the connector embodiment depicted in FIG. 8
is merely an example of one embodiment of a connector that may be used in
fitting 100 and that there are alternative embodiments of connectors
known in the art that may be used to serve the same function and/or
purpose. In certain embodiments, connector 116 is a clamp type connector.
The base of connector 116 may be attached (e.g., bolted, brazed, or
welded) to flange 110, as shown in FIGS. 5 and 6. Operation of the clamp
portion of connector 116 may be controlled using connector screw 146,
shown in FIGS. 5, 6, and 8. Connector screw 146 may be operated (e.g.,
rotated clockwise or counterclockwise) to either open or close the clamp
of connector 116. In certain embodiments, connector screw 146 is operated
to close the clamp and close seal 144 around the shaft of gear 140, as
shown in FIGS. 5 and 6. In certain embodiments, connector screw 146
and/or gear 140 are operable using a remotely operated vehicle (an ROV).

[0054]In certain embodiments, bucket 118 is coupled to connector screw
146. Bucket 118 may be, for example, a torque bucket or other device that
allows connector screw 146 to be more easily operated (e.g., the bucket
allows more torque to be applied to the connector screw to rotate the
screw). Bucket 118 may also act as a guide or "dock" for a robot arm
(e.g., an arm of an ROV) to engage connector screw 146. For example,
bucket 118 may be an industry standard torque bucket designed per API
(American Petroleum Institute) 17D specifications.

[0055]In certain embodiments, bucket 114 is coupled to connector 116, as
shown in FIGS. 5 and 7. Bucket 114 may be, for example, a torque bucket
or other device that allows gear 140 to be operated (e.g., the bucket
allows more torque to be applied to the gear to rotate the gear). Bucket
114 may also act as a guide or dock for a robot arm (e.g., an arm of an
ROV) to engage gear 140. For example, bucket 114 may be an industry
standard torque bucket designed per API (American Petroleum Institute)
17D specifications.

[0056]In some embodiments, connector 116 and/or connector screw 146 are
operated using other types of operators. In some embodiments, the
connector and/or the connector screw are operated using operators such
as, but not limited to, a handle, a wheel, or a wrench-operated device.
Such operators as the handles wheel, or wrench-operated device may be
operable in shallow water applications of fitting 100 where manual
operation of the fitting is possible.

[0057]In some embodiments, bucket 114 is removed (e.g., uncoupled) from
connector 116. For example, bucket 114 maybe removed from connector 116
and replaced with blind hub 148, as shown in FIG. 6. Blind hub 148 may be
coupled to connector 116 to cover the outer engagement portion of gear
140. In certain embodiments, blind hub 148 is used to provide a
metal-sealed closure over gear 140 to inhibit leaks in the gear system.
Providing a metal-sealed closure over gear 140 increases long-term
reliability of fitting 100 against leaks by providing a metal backup seal
against leaks due to deterioration of any internal seals, such as
elastomeric or polymeric seals. In some embodiments, blind hub 148 is
used to inhibit activation of gear 140 and/or inhibit damage to the gear.
For example, blind hub 148 may be used to protect gear 140 from being
accidentally hit and damaged.

[0058]In certain embodiments, fitting 100 includes two diverters. For
example, one diverter may be located in each of the passages inside
fitting 100. FIG. 9 depicts a cross-sectional representation of an
embodiment of fitting 100 with two diverters 128A and 128B. In the
embodiment depicted in FIG. 9, fitting 100 is a symmetrical fitting
(e.g., passages 124 and 126 are symmetrical about a central axis).
However, two diverters may be used in fittings that are not symmetrical
(e.g., fitting 100 depicted in FIGS. 1-4).

[0059]In the embodiment depicted in FIG. 9, diverter 128A is located in
passage 124 and diverter 128B is located in passage 126. Each of the
diverters has its own associated operating mechanisms. For example,
diverter 128A is coupled to flange 110A and drive hub 134A while diverter
128B is coupled to flange 10B and drive hub 134B. Flange 110A may be
coupled to body 102 using bolts 112A and seal 122A. Flange 110B may be
coupled to body 102 using bolts 112B and seal 122B.

[0060]Diverters 128A and 128B include openings 130A and 130B,
respectively. Openings 130A and 130B may be shaped to substantially match
the shape of the junction between passages 124 and 126 when diverters
128A and 128B are in the open positions. Diverters 128A and 128B may also
include orifices 132A and 132B, respectively. FIG. 9 depicts an
embodiment of fitting 100 with diverter 128A in the open position
(opening 130A is open to passage 126) and diverter 128B in the closed
position (opening 130B is closed off to passage 124). In such an
embodiment, passage 126 is open to flow and may be cleaned in either
direction (e.g., passage 126 is open for pigging). In an alternative
arrangement, diverter 128B is in the closed position and diverter 128A is
in the open position so that passage 124 is open to flow and may be
pigged in either direction.

[0061]FIG. 10 depicts a cross-sectional representation of an embodiment of
fitting 100 with two diverters 128A and 128B with both diverters in the
open position. In such an arrangement, passages 124 and 126 are both open
for flow simultaneously. In addition, one or both of the passages may be
pigged in the combining flow direction when both diverters are in the
open position. In another arrangement, one of diverters 128A or 128B may
be closed to direct objects larger than the diverter orifices through the
fitting in a specific passage.

[0062]In certain embodiments, a tie-back system includes fitting 100. The
tie-back system may be located at or proximate to a well (e.g., a subsea
well or subsurface well such as a production well). The tie-back system
allows the pipeline to be pigged without the use of a second return
pipeline upstream of the tie-back system (e.g., to an upstream platform).
The tie-back system may include additional piping or conduit that allows
the pig to be manipulated and turned around in the pipeline without the
use of the second return pipeline. Thus, the pig may be able to go on a
round trip through the pipeline (e.g., round-trip-pigging). In certain
embodiments, the tie-back system includes, or is coupled to, a kicker
line that allows the pig to be pressure manipulated through the tie-back
system and returned through pipeline 204 in a reverse direction from the
initial pig direction.

[0063]FIG. 11 depicts an embodiment of tie-back system 200 with pigging
capability and well energized kicker line 202. Tie-back system 200 may be
coupled to, or located in, pipeline 204 at or near well 206. In some
embodiments, tie-back system 200 is coupled to, or located in, pipeline
204 at other locations along the pipeline. In certain embodiments,
tie-back system 200 includes sections of piping or conduit coupled to
pipeline 204 and well 206. In certain embodiments, fluid in tie-back
system 200 flows through pipeline 204 from well 206 to upstream 208.
Upstream 208 may include facilities, other piping, or other conduits that
are upstream of well 206. For example, floating platforms, fixed
platforms, template structure platforms, offshore oil rigs, oil drilling
ships, onshore platforms or facilities, intermediate processors, final
processors, distribution facilities, production vessels, plants, or
refineries may be located upstream of well 206. Well 206 may include, but
not be limited to, production wells (e.g., oil production wells, slurry
production wells, and solid production wells such as subsea production
wells or subsurface production wells) and fluid injection wells (e.g.,
subsea injection wells or subsurface injection wells).

[0064]In certain embodiments, a user may send a pig through pipeline 204
using, for example, a pig launcher/receiver. For example, the pig may be
launched from upstream 208 through the pig launcher/receiver. Pig
launchers/receivers are used to launch and/or receive pigs used in
pipeline 204. Pigs may be used, for example, to clear debris inside
pipeline. In some embodiments, pig launchers/receivers are located on or
coupled to a platform (e.g., a platform located upstream 208). In some
embodiments, pig launchers/receivers are subsea pig launchers/receivers.
Subsea pig launchers/receivers may be coupled to pipe runs and/or other
piping, conduits, and fittings used to operate the pig.

[0065]The pig may be propelled to well 206 or to the proximity of the well
to clear debris in pipeline 204 and/or tie-back system 200. The pig may
then be returned through pipeline 204 using pressure manipulation of the
pig in the pipeline and tie-back system 200. In certain embodiments, the
sections of piping in tie-back system 200 form a loop so that the pig
moves through the loop to reverse the direction of the pig in pipeline
204 and the pig is returned through the pipeline in the reverse direction
from the initial pig direction.

[0066]In certain embodiments, tie-back system 200 includes one or more
fittings 100. Fitting 100 may be coupled to pipeline 204 at or near a
junction of the pipeline and tie-back system 200. In certain embodiments,
fitting 100 couples pipeline 204 to tie-back system 200. Fitting 100
allows the pig to enter tie-back system 200 from pipeline 204 and exit
the tie-back system back into pipeline 204 going in the opposite
direction to the direction that the pig entered the tie-back system.

[0067]In certain embodiments, tie-back system 200 includes one or more
valves 210 and/or one or more pig monitoring devices 212. Valves 210 may
be used on one or more of the portions of piping on either side of
fitting 100. Valves 210 may be used to close off or isolate one or more
sections of tie-back system 200 and/or isolate the tie-back system from
pipeline 204. For example, valves 210 may be used to shut off tie-back
system 200 or sections of piping in the tie-back system. In certain
embodiments, valves 210 are valves such as, but not limited to, ball
valves and gate valves. In some embodiments, valves 210 are operable
using an ROV, an AUV (autonomous underwater vehicle), remote operation, a
human operator, or a human operator in an atmospheric suit. In certain
embodiments, tie-back system 200 includes at least one check valve 214.
Check valve 214 may limit the flow of fluid (and thus, the pig) to one
direction through tie-back system 200.

[0068]Pig monitoring devices 212 may include, but not be limited to, pig
sigs. Examples of pig sigs include PIG-SIG® IV and PIG-SIG® NI
available from T.D. Williamson, Inc. (Tulsa, Okla., U.S.A.). Pig
monitoring device 212 may be used to monitor the passage of the pig by
the location of the device. Pig monitoring devices 212 may provide other
information such as, but not limited to, pig velocity and pig passage
time and date.

[0069]In certain embodiments, tie-back system 200 includes kicker line
202. Kicker line 202 may be a manifold of pipes and/or valves. Kicker
line 202 may provide fluid pressure to push and/or propel the pig along
the pipeline. In some embodiments, kicker line 202 provides fluid
pressure to propel the pig past well 206 in tie-back system 200. In some
embodiments, as shown in FIG. 11, kicker line 202 is energized by fluids
from well 206. Valves 210 coupled to kicker line 202 may be used to
operate and control the pressure through the kicker line.

[0070]In some embodiments, kicker line 202 is energized by fluids provided
from another source (e.g., an upstream source such as a host platform).
FIG. 12 depicts an embodiment of tie-back system 200 with pigging
capability and upstream energized kicker line 202. Upstream 208 may
provide fluids to kicker line 202. In some embodiments, kicker line 202
is energized with fluids from downstream or lateral of the kicker line.
Kicker: line 202 may be used to propel the pig along tie-back system 200
towards well 206A. Well 206A may be coupled to well 206B with piping or
conduit. In some embodiments, well 206A and well 206B are one well
coupled to tie-back system 200.

[0071]In some embodiments, upstream 208 provides fluid and pressure to
push the pig through two or more tie-back systems (e.g., the upstream
services two or more tie-back systems). For example, upstream 208 may
provide fluid to more than one kicker line 202 with each kicker line
being coupled to one tie-back system. Thus, a single riser on a host
platform upstream 208 could be used to provide fluid to several kicker
lines. Using the single riser instead of several different risers may
lessen the dynamic load on the host platform. The riser for the kicker
lines is typically smaller than risers used for pipeline 204. Thus, using
the kicker lines to propel the pig through the tie-back systems may
reduce the load on the host platform or other upstream service source.

[0072]Coupling one or more tie-back systems 200 to kicker line 202 allows
the kicker line, pipeline 204, and/or other piping or conduits to be
installed and/or moved into a final position before host services are
installed and coupled to piping or conduits. In certain embodiments,
tie-back system 200 includes at least one termination point for a well
control or valve control umbilical. Terminating the well control
umbilical in tie-back system 200 allows the well control umbilical to be
used to control valves 210 and/or fitting 100 in the tie-back system. In
addition, having the termination point in tie-back system 200 allows an
umbilical from tie-back system 200 to well 206 to be installed and/or
moved into final position before host services are installed.

[0073]In some embodiments, kicker line 202 is a small diameter injection
pipeline. FIG. 13 depicts an embodiment of tie-back system 200 with
pigging capability and small diameter kicker line 202. In some
embodiments, small diameter kicker line 202 may be used to provide
injection fluid to well 206A or 206B if either of these wells is an
injection well or requires injection.

[0074]In some embodiments, the pipeline system includes future development
added at later times. Use of tie-back system 200 with fitting 100 and
kicker line 202 allows for future pipeline system development. FIG. 14
depicts an embodiment of tie-back system 200 with pigging capability,
kicker line 202, and future pipeline system development 216. Future
pipeline system development 216 may include piping 218, wells 206C, 206D,
valves 210, and other needed components or devices. In some embodiments,
kicker line 202 is a small diameter kicker line. In some embodiments,
kicker line 202 originates from a well (e.g., well 206B). Future pipeline
system development 216 may be added at later times, for example, as the
size of the field development increases. In some embodiments, one or more
tie-back systems 200 are added as part of future pipeline system
development 216.

[0075]FIG. 15 depicts an embodiment of pipeline system 220 for using
single pig launcher/receiver 222 with multiple pipeline branches 204A,
204B, 204C. Three pipeline branches are shown in the embodiment depicted
in FIG. 15. It is to be understood, however, that any number of pipeline
branches may be used as desired or needed. At least one fitting 100 is
located at the junctions of branch 204A, branch 204B, and/or branch 204C
with pipeline 204. The pig may be launched using pig launcher/receiver
222 and then directed into a desired branch (either branch 204A, branch
204B, or branch 204C) using one of fittings 100. In some embodiments, pig
launcher/receiver 222 is used to receive the pig from one of the
branches. Using fittings 100 at the junctions of pipeline 204 and
branches 204A, 204B, 204C allows one pig launcher/receiver 222 to be used
for the branches in pipeline system 220. Using one pig launcher/receiver
222 may reduce the load on a host platform and/or reduces costs
associated with installation, use, space required, and/or maintenance of
the pig launcher/receiver in any location.

[0076]FIG. 16 depicts an embodiment for using fitting 100 for coiled
tubing access. Pipeline 204 may be coupled to fitting 100. Fitting 100 is
coupled to coiled tubing insertion apparatus 224 and pipeline 226.
Pipeline 204 may be coupled to host platform 228. In some embodiments,
pipeline 204 is coupled to another facility or another pipeline. Fitting
100 allows fluid to be produced from well 206 while also allowing access
to pipeline 204 for coiled tubing insertion by apparatus 224 or for
allowing access for other apparatus.

[0077]It is to be understood the invention is not limited to particular
systems described which may, of course, vary. It is also to be understood
that the terminology used herein is for the purpose of describing
particular embodiments only, and is not intended to be limiting. As used
in this specification, the singular forms "a", "an" and "the" include
plural referents unless the content clearly indicates otherwise. Thus,
for example, reference to "a bolt" includes a combination of two or more
bolts and reference to "a fluid" includes mixtures of fluids.

[0078]Further modifications and alternative embodiments of various aspects
of the invention will be apparent to those skilled in the art in view of
this description. Accordingly, this description is to be construed as
illustrative only and is for the purpose of teaching those skilled in the
art the general manner of carrying out the invention. It is to be
understood that the forms of the invention shown and described herein are
to be taken as the presently preferred embodiments. Elements and
materials may be substituted for those illustrated and described herein,
parts and processes may be reversed, and certain features of the
invention may be utilized independently, all as would be apparent to one
skilled in the art after having the benefit of this description of the
invention. Changes may be made in the elements described herein without
departing from the spirit and scope of the invention as described in the
following claims.